Among many gas wells in North America alone, the vast majority are mature, produce less than 100,000 standard cubic feet per day (100 Mscfd) of natural gas, and are often hampered by liquid accumulation.
In the early life of a natural gas well, the gas generates enough pressure to drive liquids present in the formation, which include water or natural brines and hydrocarbon condensates, out of the well. As the well ages, the gas velocity declines, and liquid begins to accumulate in the well. When the well becomes loaded with liquid, production diminishes and eventually becomes erratic or ceases altogether.
Various methods have been developed to combat the problem of liquid accumulation in gas wells. Some are discussed, e.g., in U.S. Pat. No. 7,422,064. For instance, the flow can be temporarily interrupted to allow enough time for sufficient pressure to build. When the pressure is released, some of the accumulated liquid can be unloaded. Surfactant “sticks” (see, e.g., U.S. Pat. No. 5,515,924) have been used without complete success.
In another approach, foaming agents are injected periodically or continuously into the well (see, e.g., M. Willis, “Chemical Gas Well Deliquification,” Explor. & Prod., Oil & Gas Rev. 8 (2010) 103). The foaming agent, which contains one or more surfactants, reduces surface tension of the liquid mixture, and the flow of natural gas generates a foamed composition comprising the foaming agent, aqueous brine, and hydrocarbon condensates. The gas lifts the low-density foam out of the well. Ideally, the foamed mixture easily separates into aqueous and hydrocarbon phases (i.e., it “demulsifies”) after it exits the well.
Foamers typically work best with more dilute brines, higher surfactant concentrations, and/or low levels of hydrocarbon condensate. Because the kind of brine and proportion of hydrocarbon condensate are normally characteristic of the gas well, the surfactant identity and concentration are important for achieving success. Surfactants traditionally used in the foamers have included certain fatty betaine and sulfobetaine compositions, such as cocoyl betaine, lauryl betaine, myristyl betaine, cocamidopropyl betaine, cocamidopropyl hydroxysultaine, lauramidopropyl hydroxysultaine, and the like (see, e.g., U.S. Pat. Nos. 7,618,926; 7,422,064; 7,407,916; and 4,796,702).
Among the betaines and sulfobetaines useful for gas well deliquification, we recently described certain compositions prepared from metathesis-based feedstocks (see WO 2012/061098). Metathesis provides an effective way to make reduced-chain (especially C10-C17) fatty esters having monounsaturation from natural oils. The best performers had a C10 or C12 monounsaturated chain and were amine betaines, amidoamine betaines, amine sulfobetaines, or amidoamine sulfobetaines. The compositions performed well at hydrocarbon condensate levels up to 20 vol. % based on the amount of foamed composition (see Table 12 of the '098 publication).
High condensate gas wells pose a special challenge. When the amount of condensate exceeds about 40 vol. % (based on the amount of foamed composition), the surfactants normally used at lower condensate levels usually become ineffective, prompting reliance on supplemental gas injection, plunger lift devices, or expensive fluorinated surfactants. Recently, foamer compositions based on quaternized amidoamines have shown promise in unloading high-condensate gas wells (see U.S. Pat. Appl. Publ. No. 2012/0279715, especially FIG. 1).
The industry would benefit from the availability of improved foamer compositions for gas well deliquification. Of particular interest are compositions that perform well when the gas well is characterized by a high level of hydrocarbon condensates. Preferably, the compositions would be less costly to manufacture than fluorinated surfactants. Ideally, the foamers could cost-effectively unload even gas wells characterized by a very high concentration of hydrocarbon condensates.